Carbonate Formations Background
Oil-bearing carbonate formations are said to comprise over 50% of the known hydrocarbon bearing resources. The formations are predominantly comprised of calcite and dolomite with other interspersed mineralogy. Porosity in these formations results from macro features such as fractures, vugs, and breccia deposits as well as micro porous features. While the micro porous aspects tend to have quite low permeability for movement of fluids, the macro features can exhibit permeabilities of 1 to 10 Darcies or more.
Heavy oil reserves in carbonate formations are generally some of the most difficult resources to produce and recover. A prime example is the Grosmont formation in Alberta, Canada. Primary production via natural reservoir pressure may recover only a small fraction of the in situ resource. Poor primary recovery is due to both the viscous nature of the hydrocarbons with capillary forces preventing efficient recovery efforts and the carbonate wetting characteristics being highly oil wet. Because of the high viscosity, water flood secondary techniques are not viable, so operators are forced to immediately proceed to tertiary techniques employing steam, acids and/or solvents. The carbonate surfaces tend to be oil wet as certain naphthenic acid fractions convert the carbonate into the calcium salt which forms insoluble attachment points to the carbonate surfaces. To address the viscosity issues, thermal techniques, such as steam, are often employed to promote mobilization of the oil and hence flow, however the oil wet nature of carbonates still prevents free release of the oil thereby limiting possible recovery factors. Mobilization of the oil is important to developing sufficient injectivity in the case of an EOR flooding technique. Although application of heat via steam can make the matrix more water wet through a remineralization process, it tends to be slow since calcite and dolomite solubility are reduced at higher temperatures. Many of these crudes may be classified as “dead” crudes in that there is little, if any, dissolved gas associated with them to provide natural energy to assist with the recovery efforts, particularly during and after primary production.
Oil Recovery Challenges in Carbonate Formations
When primary and secondary production methods have been exhausted, or when the formation is such to preclude primary production, in some reservoirs enhanced oil recovery (EOR) methods can be used to recover additional oil. Carbonate matrix formations are formed by fractured and karsted dolomitic rocks. Carbonate reservoirs composed of calcite and dolomite offer a unique challenge to enhanced oil recovery because they often display oil wet to mixed wet characteristics. “Wettability” describes the preference of a solid to be in contact with one fluid rather than another and affects relative permeability, saturation profiles, water flooding, aquifer encroachment into a reservoir, and other properties of the formation. “Water wet” formations prefer to be in contact with water (compared to oil), while “oil wet” formations prefer to be in contact with oil (compared to water). Water wet surfaces have an adhesive attraction of the water greater than the cohesive attraction of the water molecules for one another. Oil wet surfaces have an adhesive attraction of the oil greater than the cohesive attraction of the oil molecules for one another. Wettability can be quantified by the contact angle that the liquid makes with the contacting surface. For example, if water is used as a drive fluid, it displaces oil at the solid surface in a water wet system but advances over the oil in an oil wet system. “Mixed wetting” describes materials that have inhomogeneous wetting, which is a variety of wetting preferences. “Mixed wetting” (having a variety of wetting preferences) is different than “neutral wetting” (lacking a strong wetting preference).
Oil wet to mixed wettability in carbonate formations is a result of the chemistry that has occurred over geologic time making the heavy oil/bitumen difficult to release from the surfaces. Reservoirs are complex structures, often comprising a variety of mineral types. Each mineral can have a different wettability preference, making the overall wetting character of the composite rock difficult to describe and difficult to plan effective oil recovery operations around. Many carbonate reservoirs are naturally fractured geologic formations with overall low porosity but a heterogeneous distribution of permeability. High permeability of the fractures and low pore volume in the fracture network leads to early breakthrough of injected fluids in the producing wells and less than optimal hydrocarbon recovery from these formations. As a result, very few EOR methods work effectively for fractured oil-wet carbonates.
This is particularly the case in the heavy oil carbonate fields of Canada that have a moderate to high acid content. Certain acidic components of these crude oils, such as naphthenic acids, react with the calcium or magnesium from the carbonate reservoirs to create the naphthenate salt form of the acid, which has low solubility in water. These naphthenate salt forms are like the well-known insoluble soap scums that form from detergents in hard water. The insoluble oil phase salts then provide potential oil attachment points to the carbonate surface making the carbonate preferentially oil wet (oil-preferring). On the other hand, the sodium or potassium naphthenate salts act as surfactants to help reduce interfacial tension (IFT) and to release oil from the surface. These soluble forms are a natural consequence of alkaline flooding and promote a water wet (water-preferring) surface.
Wettability Alteration in Carbonates
Various alkalis such as silicates have been shown to alter wettability to a more water-wet state at low temperatures, but most suffer from very high consumption rates at elevated temperatures where the alkaline chemical slugs become quickly spent before propagating deep into a carbonate formation. The consumption is the result of alkali precipitation reactions with the hardness ions (Ca2+, Mg2+, etc.) generated by the limestone/chalk minerals in the reservoir/formation.
High temperatures (from steam or hot water flooding, for example) can alter wettability from oil wet to more water wet as Mg, Ca, CO3,or SO4 containing minerals tend to dissolve and re-deposit as fresh surfaces depending on chemical equilibria which vary as a function of temperature. Wettability is then controlled by spreading forces and adhesion forces on these new surfaces. However, there is often a prolonged incubation time associated with this process before water wet conditions are actually achieved.
Other wettability altering methods have been attempted such as injecting carbon dioxide, sulfur dioxide and/or nitrogen dioxide, to form acidic liquids or vapors to dissolve minerals and alter equilibria. When combined with water or steam and injected during in-situ recovery operations, the acidic liquids/vapors alter wettability from oil to water wet. Other methods use a stepped salinity gradient or dilute surfactants to alter wettability so more oil is released.
Other techniques have been proposed and attempted for improving the oil recovery efficiency from oil-bearing carbonate formations, but still large volumes of hydrocarbons remain in oil-rich formations after secondary and tertiary recovery efforts. Numerous enhanced oil recovery technologies are currently practiced in the field including those involving thermodynamic, chemical, and mechanical displacement processes. Heating the oil with steam often reduces the viscosity of the trapped oil, provided there is ready access to steam energy and heat losses can be managed. Miscible chemicals, such as CO2 and hydrocarbon solvents also swell the oil phase to reduce viscosity but are most often used for lighter crude oils. Other chemical systems employing alkalis, surfactants, and/or polymers are less widely used often due to cost and high consumption issues.
Even with these oil recovery techniques, oil recovery from carbonate formations and reservoirs has not reached its potential. Improved methods are required to access and mobilize more of the trapped crude oil in these heavy deposits so that it can be added to the recoverable reserves. Prior systems and methods for increasing the productivity of oil wells have fallen short. A continued need exists in the art for effective oil recovery from carbonate formations and reservoirs.